1. Field of the Invention
The present apparatus relates to a fluid level control mechanism for maintaining a fluid level at a predetermined point within a well. More specifically, the fluid level control mechanism comprises a resilient force assembly, a reservoir assembly, a flow line assembly, and upper and lower centralizers for controlling the fluid level in a well by diverting some production fluid, as necessary, back into the well to maintain the fluid level at the predetermined point.
2. Description of the Related Art
When a well is not being produced, the fluid level in the well will rise due to the pressure in the well's production formation. The fluid level will continue to rise until the column of fluid in the well bore exerts a pressure on the formation equal to the formation pressure. At this point, fluid from the formation will stop flowing into the well and the fluid level will stop rising. This level is called the static fluid level. Once the well is put into production the fluid level in the well bore will begin to drop. As the fluid level drops, pressure on the formation is relieved and fluid from the formation will begin to flow into the well. If the fluid level continues to drop, more fluid will flow from the production zone at an increasing rate. If less fluid is pumped out of the well than the formation can produce, the fluid level will eventually stabilize at some point above the pump. At this point, fluid being pumped out of the well equals fluid flowing into the well. If more fluid than the production formation can produce is pumped out of the well, the fluid level will drop to the level of the pump's inlets and the pump will cavitate, eventually damaging production equipment. In this case, the pump is attempting to pump more fluid than the formation can produce. Maximum well production is achieved when all the fluid a well can produce is pumped to the surface. As such, in order to maximize well production (whether for oil, water, or gas) while simultaneously protecting production equipment, there is a need for mechanisms that will maintain the fluid level within a well to a position immediately above the pump's location in the well.
Maximum fluid production from a well is achieved when the fluid level is pulled down to the production formation and all pressure is removed from the formation. In an oil well, relieving this pressure not only maximizes the amount of fluid being produced but also increases the oil to water ratio since oil requires greater pressure relied than water to begin flowing through the formation. The most common way of producing an oil well is with a production string which consists of a pumping unit, tubing, rods, and a mechanical downhole pump. The pumping unit, located at the surface, is powered by an electric motor, pulleys, and drive belts. It produces an up and down motion which actuates the downhole pump through a series of rods which connect the pumping unit to the downhole pump. The rods run through the center of a string of tubing which also runs from the downhole pump to the surface of the well. The tubing provides a conduit for the production fluid to flow to the surface of the well. As the pumping unit strokes up and down, a plunger within the pump also strokes up and down. All the fluid, less leakage, that enters the pump is lifted to the surface. Each stroke of the pump sucks fluid into the pump and then lifts it to the surface. The amount of fluid being pumped is governed by pump size, stroke length of the pumping unit, and the number of strokes per minute. The fluid production can be slightly adjusted by changing the strokes per minute. All other variables would require considerable expense to change. The strokes per minute are adjusted by changing pulley and drive belts. This method of controlling production does not lend itself to fine adjustment of fluid flow.
A second and less common method of producing an oil well is with an electrically driven downhole pump. This is also the method used for producing the vast majority of water and gas wells. The downhole pump is connected to the bottom of a tubing string that reaches from the downhole pump to the surface of the well. An electric motor is connected to the bottom end of the pump. An electrical power cable extends from the surface to the pump motor and provides the power to run the motor. The motor drives the pump, which pumps fluid through the tubing to the surface of the well. This method of pumping gives a relatively constant flow rate which can be somewhat adjusted with the use of flow control valves. Flow control valves cannot be used with pumping units since they produce a given amount of fluid with each stroke regardless of valve opening.
Both methods of pumping run into problems if the fluid level in the well is pulled down to the level of the pump's inlets. This will happen if the pump produces more fluid than the well's formation can give up. In the case of mechanically driven pumps, the pump's intake chamber will not completely fill with fluid during each pumping unit stroke, resulting in air entering the chamber. This causes a pounding or jarring effect with each production stroke. The pump will continue to produce under this condition but, in time, the constant pounding will damage the pump, the production string, and the pumping unit. In the case of an electrically driven pump, the consequences are even more severe. Should the pump run dry, both the motor and the pump can be severely damaged in a very short time. If the pump runs dry, it will begin to heat up thereby damaging rings, seals, and the impellers within the pump, causing the pump to quickly fail. Furthermore, the motor on an electrically driven pump is located below the pump and needs a constant flow of fluid to cool the motor. If the pump fails, the cooling flows of fluid past the motor will stop and the motor will overheat and burn out within a short period of time.
As such, one would desire to pick a pump which produces the same amount of fluid as the well gives up. In the case of mechanically driven pumps, this simply cannot be done for several reasons. First, pumps do not come in an infinite range of production rates. Second, the use of pulleys, belts, and stroke length to adjust flow rates does not lend itself to the fine adjustments necessary to match the formation rate. In the case of electrically driven pumps, the production rates can be more easily controlled through the use of control valves. However, electrically driven pump rates are affected by a number of factors that do not affect mechanical pumps. These factors also interact with each other and include, but are not limited to, frictional losses in the piping system, changes in downstream pressure in the production lines, pump and motor wear and loss of efficiency, changes in supplied voltage and amps, changes in the production fluid's viscosity, and changes in the amount of fluid a well can give up at any given time. Frictional losses, for example, are a function of rate of fluid flow. As the flow rate changes, the frictional losses change. This means that as one variable changes, it affects a second variable. Changes in downstream pressure can occur if there is a change in the production rate of a downstream well. The specific gravity and viscosity of the production fluid will change as the oil to water ratio changes during normal production. All of these factors interact and make fine adjusting of flow rates next to impossible.
Furthermore, and possibly most importantly, well formations do not produce fluid at either a constant flow rate or a constant viscosity. Formation flow rates can change from day to day or even hour to hour. In oil wells, the viscosity of the production fluid is also constantly changing as more or less oil is produced. This makes it impossible to size a pump to exactly match a well's formation flow. In order to overcome this problem and avoid damaging pumps and equipment, one has had to previously maintain the fluid level in wells well above the pump inlets or utilize timers to turn pumps on and off or other devices to control production rates. These methods, however, result in inefficient production, with a decrease in both total fluid production and oil to water ratio and the starting and stopping of motors and pumps severely shortens their life span, since the life cycle of both electric motors and pumps is best when turned on and left to run constantly.
Accordingly, there is a need for a way of placing the downhole pump within or as close as feasible to the production formation while automatically adjusting the amount of fluid being produced from the well so as to pull the fluid level down to just above the pump's inlets and maintain it at this level.